This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the presently disclosed invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the presently disclosed invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Production of natural gas from low-permeability shale formations is rapidly increasing in the United States and elsewhere. For example, the Barnett shale in northern Texas has produced more than 3.3 trillion cubic feet (tcf) since 2000 and currently produces more than 3.1 billion cubic feet per day (bcfd). Recoverable natural gas reserves for the Barnett shale alone are estimated to be in the range of 7-20 tcf.
Shales that host economic quantities of natural gas may have a number of common properties. In general, they are very fine-grained sedimentary rocks that are rich in organic material (e.g., 0.5% to 25%) and are usually mature petroleum source rocks in the thermogenic gas window, where high heat and pressure have converted petroleum to natural gas. They are sufficiently brittle and rigid enough to maintain open fractures. The gas content of such shales typically is in the range 30 to 500 standard cubic feet per ton of shale. The natural gas found in shale formations is formed primarily of methane, but it can also include ethane, propane, butane, and pentane and inert components such as CO2, N2, and H2S. The composition of natural gas can vary widely, but Table 1 shows the contents of a typical unrefined natural gas supply.
TABLE 1Composition of Natural Gas (typical)MethaneCH470-90%EthaneC2H6 0-20%PropaneC3H8ButaneC4H10Carbon DioxideCO20-8%OxygenO2  0-0.2%NitrogenN20-5%Hydrogen sulfideH2S0-5%Rare gasesA, He, Ne, XeTrace
Despite the rapid increase in exploitation of shale gas resources, there are significant opportunities for optimization of gas production rate and recovery. Shale has low matrix permeability, so gas production in commercial quantities requires fractures to provide permeability. Gas shale formations may contain natural fractures, but hydraulic fracturing is generally required to induce additional fractures and enable economic production of the gas. Presently the preferred method for primary production of gas from shale generally consists of drilling a horizontal well and then performing multiple slick-water fracture jobs. Slick-water fracturing is a hydraulic fracturing treatment using water with viscosity reducer. This method enables typical initial well rates in the range of 3-10 million cubic feet per day (mcfd). Published estimates indicate that this method only recovers between 5% and 20% of the available gas. Such rates and recovery factors are much lower than those typically achieved in conventional gas resources.
The exact mechanism by which natural gas is stored in low-permeability shale is not well understood; however, much of the gas is believed to reside as free gas in the tight pore space within the shale and in natural fractures. In addition, a significant fraction of the gas is believed to be adsorbed onto organic material and clays within the shale. These mechanisms are similar to the dominant methane storage mechanisms in coal-bed methane deposits and it is believed that CO2 will displace and replace adsorbed methane in coal.
It is also anticipated that, in the future, there will be significant incentives to store large quantities of CO2 underground to reduce greenhouse gas emissions to the atmosphere. Conventional research is focused on deep saline formations as the primary geologic medium for subsurface CO2 storage. However, there are significant challenges associated with storing CO2 in deep saline formations. For example, the deep saline formations would need to be close to the sources of CO2 and the subsurface formations would need to have a suitable trap and top seal so that the CO2 does not escape for periods exceeding centuries. Another major concern is the disposition of the large volumes of brine that will be displaced by the injected CO2.
It has been suggested that a potential solution might be to inject CO2 into shale formations both to enhance displacement of the in-place natural gas and to store CO2. As such there is a need for an improved method for facilitating such displacement of natural gas and storage of CO2.